Fuel compositions from light tight oils and high sulfur fuel oils

ABSTRACT

Methods are provided to prepare a low sulfur fuel from hydrocarbon sources, such as light tight oil and high sulfur fuel oil, often less desired by conventional refiners, who split crude into a wide range of differing products and may prefer presence of wide ranges (C3 or C5 to C20 or higher) of hydrocarbons. These fuels can be produced by separating feeds into untreated and treated streams, and then recombining them. Such fuels can also be formulated by combinations of light, middle and heavy range constituents in a selected manner as claimed. Not only low in sulfur, the fuels of this invention are also low in nitrogen and essentially metals free. Fuel use applications include on-board large marine transport vessels but also on-shore for large land based combustion gas turbines, boilers, fired heaters and transport vehicles and trains.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a divisional of U.S. Ser. No. 16/089932 filed 28Sep. 2018, which is a 371 National Phase of International ApplicationSerial No. PCT/US2016/057546 filed 18 Oct. 2016, both of which areincorporated herein by reference.

FIELD OF THE INVENTION

This invention provides novel methods to make fuel and preparecompositions that simulate fuels having a wide range (C3 or C5 to C20+or higher) of hydrocarbons produced from crude oil. Preferred feeds toprocesses of this invention are hydrocarbon sources not always preferredby conventional refiners as feedstock, such as for illustration,refinery intermediate residues, high sulfur fuel oils, lower sulfur fueloils or light tight oils, condensates, extra heavy crude, tar sands, anddilbits. The fuels provided by this invention are ultraclean fuel, beingvery low in sulfur and nitrogen, with so low in metals by manymeasurement techniques, they are hard to detect and essentially metalsfree and are especially cost effective not only for use on-board largemarine transport vessels but also on-shore for large land basedcombustion gas turbines, boilers, and transport vehicles and trains.

BACKGROUND OF THE INVENTION

This invention targets at least three issues: (1) conversion of lowvalue hydrocarbons to higher value fuels, (2) cost effective reductionof sulfur and nitrogen, and substantial elimination of metals from suchfuels and (3) tailoring such fuels for use in marine or land basedengines, combustion gas turbines, or fired heaters such as boilers.

Certain hydrocarbon sources are not desired as refinery feeds and thusmay be assigned a low value by refiners. Conventional refiners seek tosplit each barrel of crude having a full or broad range of hydrocarbonsinto multiple fuel products and feedstocks from downstream chemicalsmanufacture. Refiners often prefer feeds having a broad range ofhydrocarbons. To compete in an arena that often has very narrow margins,certain refiners need most of a full carbon range of crudes to completematerial and energy balances required to seek to fill all unitoperations, as well as meet customer supply commitments, but thoserefiners also prefer feeds that do not pose processing challenges orincrease processing costs.

Conventional refineries face processing issues, for example, with veryheavy crudes such as Maya (Mexico), BCF-17 (Venezuela) and Oriente(Equador) offering apparatus, operating and investment cost challenges,which likewise may arise also with processing of oil shales derived fromorganic rich sedimentary kerogen-containing rocks and condensates.

Conventional refineries also face processing issues with light tightoils, which one might describe, when comparing to crude oil, as ‘missingmost of the bottom of the barrel’. Light tight oils (also referred tosimply as tight oils), now widely available as being produced fromshales and other low permeability formations such as sandstone orcarbonates. Compared to conventional crude oils, tight oils may haveexcessive light ends but relatively little or no hydrocarbons within theranges refiners might refer to as “vacuum gas oil” range or “heavyresidual” or “vacuum resid” ranges, boiling above about 425° C. or 565°C. respectively, or ‘bottom of the barrel’ heavy range materials. SeeRefining America's New Light Tight Oil Production, OPIS 16^(th) AnnualNational Supply Summit, Las Vegas October 2014) Baker & O'Brien.

The term “tight oil”, “light tight oil” or “LTO”, as used herein means awell head condensate, non-associated natural gas condensates, or shalegas condensate having (i) sulfur content in the ranges of nearly notmeasureable or none (0) wt. % to 0.2 wt. %, a (ii) a density, API (Deg)in the range of 38 to 57 degrees, (iii) traces of metals and (iv) widevariations of hydrocarbon ranges based sources. Not all are the same.LTOs from different sources will differ in distillation cut fractionranges. Using description of ranges certain refiners may use tocharacterized fractions, illustrative variations of LTO may comprise (a)5 to 20 wt. % liquefied petroleum gas range, (b) 10 to 35 wt. % naphtha,(c) 15 to 30 wt. % kerosene/jet range, (d) 15 to 25 wt. % diesel andheavier distillates, (e) trace to 10% or more vacuum gas oils and (f) no(0%) to about 5 wt. % or more heavy residuals.

Such light tight oils, especially those with trace heavy gas oil andessential no or very low heavy residuals, do not contain sufficientheavier hydrocarbons within its bottoms fractions within gas oil andresiduals ranges to providing processing balance for desulfurization orother hydrotreating, nor corresponding residuals sufficient to supportprocess hydrogen generation to enable cost effective processing suchlight crude to hydrogenate to lower sulfur and metals fordecontamination or have sufficient lubricity to support use in certaintypes of engines. See for illustration “The North Dakota PetroleumCouncil Study on Bakken Crude Properties Bakken Crude CharacterizationTask Force” (2014), Turner & Mason provides composition ranges forcertain tight oils. Those skilled in the art appreciate that, in orderto balance the mix of product cuts from a crude distillation tower tofit many refinery operations, blending tight oils with heavy asphalticcrude makes sense, as the blend can result in a desirable distillationprofile for many refiners. However, this practice can also lead tocompatibility issues, for example, asphaltene destabilization. See“Overcoming the Challenges of tight/shale oil refining”. ProcessingShale Feedstocks (2014) Benoit et al.

Processing issues are also faced by conventional refineries with highsulfur fuel oils or “HSFO”, which one might describe, when comparing tocrude oil, as being part of the ‘bottom of the barrel’ or ‘missing mostof the top of the barrel’. In different usages in the art, the term“high sulfur fuel oil” or “HSFO” has been assigned different, oftendissimilar, conflicting and confusing means in various technicalarticles, patents, and statutes, some of which change over time. Broaduse of the phrase ‘high sulfur fuel oil’ has been used to describe awide range of materials, including those outside of use of fuels,ranging from lighter, lower boiling, but high sulfur (hence high smoke)kerosene to heavy marine bunker fuels having greater than 3.5 wt. %sulfur content or to masut or other heavy residual ‘bottom of thebarrel’ materials, which in some instances do not have a clear oruniformly applied specification. Certain index reporting systems baseHSFO on RMG 3.5% sulfur quality fuel oil per ISO 8217 specifications,while others use different sulfur content.

As used in the specification and claims, “high sulfur fuel oil” or“HSFO” means any material used as fuel having sulfur content in excessof 0.50% m/m (0.5 wt. %). As used herein, the terms “heavy oils”, “heavyresidual oil”, “residuals”, “residue” or “other heavier oils”, “tarsand” and “extra heavy crude” such as petroleum derived hydrocarbonaeousmaterials having a sulfur content in excess of 0.50% m/m (0.5 wt. %).The term “high sulfur” means above the target sulfur content limit of afuel or statutory sulfur limit where applicable, whichever is lower.

Another issue is that markets for high sulfur fuel oil have beenreduced, and large quantities of HSFO are un-blendable orun-transportable. In many countries where power plants fired HSFO tosupply electricity utility demands, natural gas has been substituted dueto local supply. For illustration, during about 2015, Mexico became anexporter of HSFO instead of a net importer, when power plants convertedto local supplies of natural gas.

For example, in parts of the United States, some states have changedtheir requirements for home heating oil to 500 ppmwt or less sulfur inlieu of 2,000 ppmwt sulfur or higher. One result has been that certainpipelines and distribution networks refuse to transport ‘high sulfurfuel oil’, with an associated impact being oversupply of high sulfurfuel oil in certain areas, especially where local refiners do not havefeeds, apparatus or technology to efficiency process low sulfur fueloil. For many refinery managers, there is no practical residue upgradingchoice for dealing with HSFO investment returns for the required capitalexpenditures would be much lower than alternative investments. Use ofHSFO for turbine fuels leads to corrosion and fouling problems, and lostreliability.

Prior art refinery designs use atmospheric crude and/or vacuumdistillation units, solvent separations, hydrotreating, gasification,and many other unit operations, to split each barrel of crude feed intomultiple products each with different specifications for differentapplications or downstream processing.

With hydroskimming refineries, crude is converted to multiple productsakin to topping refineries, but typically with the limited addition ofheavy naphtha reformers that also generate hydrogen which is consumed byhydrotreaters in producing diesels. Hydroskimmers, like toppingrefineries, typically make a wide range of gasoline, kerosene, dieseland fuel oil for local consumption, not just one product. Variousaspects of adapting hydrotreating, including having separate series orparallel hydrotreating reactor zones or having integrated hydrotreatingreactor zones, are known in art. PCT/US1999/00478 (1998) published byCash et al, and the references cited therein, disclose integratedhydrocracking and hydrotreating of dissimilar feeds, wherehydrogen-containing and liquids-containing streams from separatehydrotreating zones are shared or combined in the manner disclosedtherein.

Treating heavy crudes and residuals by residue hydroconversion viaebullated bed reactors has been known in the art since early ebullatedsystems were described in U.S. Pat. Nos. 2,987,465 (1961) and 3,197,288(1965) to Johanson. An ebullated-bed reactor includes flowing contact ofheavy hydrocarbon liquids with hydrogen in the presence of catalystwithin a reactor vessel, with associated various ancillary gas/liquidseparators and hydrogen makeup and recycle streams, and sulfur containgas treatment systems, are well known and commercial practiced in theart. U.S. Pat. No. 6,270,654 to Colyar et al describes series ebullatedreactors and U.S. Pat. No. 6,447,671 describes hydroconversion step viaan ebullated reactor and a hydrotreating step via fixed bedhydrotreater. Publication number US20140221713 A1 (U.S. Ser. No.13/758,429) 2014 by Baldassari et al describes various hydroconversion,hydrocracking and hydrotreating catalyst as well hydroconversion,hydrocracking and hydrotreating processes including variations ofintegrated hydroconversion, hydrocracking and hydrotreating apparatus.Baldassari et al further summarizes variations of catalyst compositionsand condition ranges for distillate and heavy oil hydrotreating anddistinguishes over conditions for hydrocracking and for residuehydroconversion, all of which are known those skilled in the art ofhydroprocessing.

Various aspects of use of solvent separation, to extract deasphalted oilfrom pitch within heavy residual streams, and use the deasphalted oil asfeed to hydroprocessing are known in art when used to produce multipleproduct streams. For example, U.S. Pat. No. 7,686,941 (2010) to Brierleyet al discusses solvent deasphalting for production of deasphalted oil,without cracking or degradation by separation of the feed based onsolubility in a liquid solvent, such as propane or other paraffinicsolvent such butane and pentane and pitch residue which contains a highmetals and sulfur content. In Brierley, the deasphalted oil ishydrocracked and hydrotreated for sulfur, nitrogen and metals removal asdiscussed in such reference for production of several products includingnaphtha, kerosene, diesel and a residual material.

Publication PCT/FR2006/000671 (U.S. Ser. No. 11/912,771) 2009 to Lengletdescribes a process for pre-refining crude oil for the production of twoasphaltenic oils and an asphaltenic oil involving pre-distillation,vacuum distillation, solvent deasphalting, hydrotreating, hydrocrackingand residue hydroconversion to produce multiple products. “RevampingDiesel Hydrotreaters For Ultra-Low Sulfur Using IsoTherming Technology”by Ackerson et al discusses unit design, catalyst choices, hydrogenconsumption, and other operating conditions for sulfur removal byhydrogenation to produce a product containing less than 8 ppm sulfur byuse of a high activity Ni/Mo catalyst. “Optimizing HydroprocessingCatalyst Systems for Hydrocracking and Diesel HydrotreatingApplications, Flexibility Through Catalyst” by Shiflet et al, page 6Advanced Refining Technologies Catalagram Special Edition Issue No.113/2013 also discusses hydroprocessing to 10 ppm or less levels usinghigh activity CoMo catalyst to remove unhindered sulfur and a highactivity NiMo catalyst for remaining sterically hindered sulfur.

Thus while many improvements have been made to address technical issuesarising from processing light tight oils and heavy residues inconventional refineries, significant problems remain without solutions.Such issues continue to cause technical gaps resulting in substantialunder-utilization of light tight oils and high sulfur fuel oils

BRIEF SUMMARY OF THE INVENTION

This invention fills a technical gap enabling use of light tight oilsand high sulfur fuel oils in effective low cost production of largequantities of fuels having very low sulfur and nitrogen, and essentiallymetals free. Such fuels are particularly useful offshore in marineapplications as well as in large scale onshore applications such ascombustion gas turbines for power generation. As used in thespecification and claims, the terms “essentially metal free” or “zerometals” means metals content of zero to less than 100 ppb (parts perbillion) or less or a content which is so low that it is difficult tomeasure reliably by conventional online instrumentation.

This invention provides novel methods to prepare from high sulfur fueloil and light tight oil a composition which simulates a fuel producedfrom crude, which fuel has a wide range (C3 or C5 to C20+ or higher) ofhydrocarbons. Preferred feeds to processes of this invention arehydrocarbon sources not always preferred by conventional refiners asfeedstock, such as for illustration high sulfur fuel oils or light tightoils.

The fuels provided by this invention are ultraclean fuel, being very lowin sulfur and nitrogen, essentially metals free and are especially costeffective not only for use on-board large marine transport vessels butalso on-shore for large land based combustion gas turbines, boilers, andtransport vehicles and trains.

In conventional refining, crude oil feed is cut into many pieces, andeach piece is sent down a separate market path. Opposite thereto, wehave found that we can take a ‘top of barrel’ light tight oil and a‘bottom of the barrel’ high sulfur fuel oil, and combine them in a lowcost manner to produce a fuel, simulating a fuel manufactured from crudeoil and having a wide range of hydrocarbons.

This invention provides a low cost system to combine light tight oilswith residual oils in a low cost manner to make large commercialquantities of clean fuels that replace high sulfur bunker fuels andother heavy residuals used in commercial transport ships and power plantcombustion systems. This invention provides those fuels, and methods andapparatus for making such fuels, to reduce emissions of sulfur, nitrogenand noxious metals in a cost efficient manner For the shipping industry,the novel configurations of this invention provide low cost, low sulfurmarine fuels in quantities needed to meet or exceed worldwide marinesulfur reduction goals. Also, fuels of this invention also provide analternative to firing crude oil or heavy residuals in large land basedcombustion turbines deployed by utilities, for illustration, singlecycle or combined cycle power plants such as those producing electricityand desalinated water. Turbines firing the fuels of this invention havesignificantly less turbine flue gases emissions of NO_(x), SO_(x), CO2,soot, noxious metals, and other combustion byproducts, also lesscorrosion of hot zones or fouling under ash formation conditions, whenfiring a contaminated heavy crude or refinery residual oil, depending onfeed source.

These novel processes use counter-intuitive steps to lower productioncosts, while controlling final product sulfur content at or below targetsulfur levels in a surprisingly effective manner Conventional refiningdoes not separate cuts then recombine them.

For example, in the conventional art of blending, blending focus is onblending to form gasolines or blends to form diesels or blends to formjet fuels, but not blends of all separate refinery production to formjust one fuel. That is, crude oil is not separated by distillation tomany fractions, only to then all be recombined. For illustration, theart teaches away from blending any large amount of diesel rangematerials with a gasoline range. Also end-users are discouraged fromblending diesels with gasolines. Likewise, confusion surrounds the terms“kerosene” and “light distillate” because such are often assigned thesame, overlapping or even different meanings in different referencematerials instead of being uniformly defined only based on atmosphericcrude tower cut points of temperature intervals (such as from 190° C. to250° C. or 180° C. to 230° C. or other evolved standard. For example,EIA defines “Middle distillates: A general classification of refinedpetroleum products that includes distillate fuel oil and kerosene”.Thus, refinery cut points at temperature intervals are dictated byspecification for each product from a conventional refinery, which oftenare set locally and are not defined based on sulfur content. We havefound that to be less than optimal.

The term “constituent” is used herein to reflect unexpected phenomenathat we found by ‘combining constituents’ in practice of this invention,versus merely blending ingredients. Typical use of the term “ingredient”when referring to a combination of things by human intervention lendsexpectation to results by presence of the ingredient. That is, theingredient, when added, gives an expected physical or chemical propertycharacteristic to the whole.

Conventional refiners do not mix gasoline with diesel, or with treatedresidual oils to produce a fuel. Instead, cuts are separated fordiffering engine types.

What is not known to those skilled in the prior refining art until nowdisclosed by this invention is a novel fuel formulation and how toselect and procure or procure from many light (L), middle (M) and heavy(H) constituents (taught and defined hereinafter) and how best tocombine the selected constitutes to form a low sulfur, essentiallymetals free fuel. Such is much akin to a baker looking at a warehousefull of cooking ingredients but not having a recipe for the lowestcalorie cake at lowest cost and not knowing that certain surprisinginteraction phenomena occur by treating ingredients and combining themcertain way.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG.1 is a schematic drawing showing basic apparatus and process stepsfor combining untreated light tight oil with treated high sulfur fueloil to form a very low sulfur fuel.

FIG. 2 shows simplified treatment of light cycle oil and high sulfurfuel oil to produce a low sulfur fuel with an adjusted flash point.

FIG. 3 is a schematic drawing showing apparatus arrangement and processsteps for use of crude oil either alone or with light tight oil and highsulfur fuel oil to produce ultraclean fuels having very low sulfur,nitrogen and metals

FIGS. 4 and 5 teach novel fuels and recipes of combinations of one ormore Constituents comprising light (L), medium (M) and/or heavy (H)materials to form such fuel.

FIG.4 is a schematic drawing showing volume fraction and density profileof reference fuel produced by a process of this invention, and its (L),(M) and (H) ranges.

FIG. 5 shows volume fraction and density profile of a reference lightcondensate which can used as a ‘top of the barrel’ (having naturallyoccurring majority of (L) Constituents minor naturally occurring (M) and(H), which is combined with added (H) from another source such as a‘bottom of the barrel’ (H) constitute, to formulate a fuel of thisinvention.

DETAILED DESCRIPTION OF THE INVENTION

This invention provides process for conversion of varioushydrocarbonaeous feeds from sources other than conventional crude oils,either alone or combined with conventional feeds, to form a fuel whichhas wide range of hydrocarbons. In variations, fuels formed by lighttight oil feed and high sulfur fuel oil feeds have a wide range ofhydrocarbons comprising those from the lowest boiling with said lighttight oil forming said fuel up to the maximum boiling point of ahydroconverted liquids derived from high sulfur fuel oil to form saidfuel.

In one embodiment, one or more high sulfur fuel oils are fed to aresidue hydro-conversion zone and contacted with hydrogen in presence ofcatalyst at residue hydroconversion conditions in an ebullated-bedreactor to form (1) hydroconversion reactor effluent which is separatedinto hydroconverted product liquids, purge gases comprising hydrogen andsulfur and (2) unconverted oils which are directed to solventseparation. Such unconverted oil are directed to form (A) solubledeasphalted oil which is recycled as feed to the hydroconversionreactor, either separately or combined with added high sulfur fuel oilfeed to said reactor and (B) insoluble pitch which is directed to pitchtreatment. The product fuel is formed by combining all or one or moreportions of a light tight oil with said hydroconverted product liquids.In one variation, before use as part of the combination, the light tightoil is fractionated to remove overhead still gases to leave fractionatorbottoms which are combined with the hydroconversion zone product liquidsto form a fuel. In another various, a portion of the feed to the solventseparation includes added high sulfur full oil which is direct added tosolvent separation or is combined with hydroconversion reactorunconverted oil for feed to solvent separation. Also, additional highsulfur fuel oil can be combined with said soluble deasphalted oil toserve as a portion of the feed to the hydroconversion reactor. Toaddress flash point and other considerations, the light tight oil can befractionated, prior to addition to the fuel combination, to removeoverhead still gases to form an upper zone lighter fraction comprisingnaphtha range hydrocarbons and higher boiling bottoms fraction. In onevariation, and at least a portion of such lighter fraction is naphtharich and can be directed to a reformer or other aromatics unitoperation, where it is subject to contact with hydrogen under reformingconditions to form a light treated stream. In another variation, all ora portion of said light treated stream, untreated light stream and highboiling bottoms fraction are combined with said hydroconverted liquidsto form a fuel. In yet another variation, the effluent from thehydroconversion reactor can be separated by fractionation into more thanone treated liquid fractions, at least one of such fractions having asulfur content above the target sulfur content which is directed as partof the feed to residue hydroconversion reactor or as part of the feed tosolvent separation

In one embodiment, the residue hydroconversion zone integrates a residuehydroconversion reactor with a heavy oil range hydrotreater and adistillate range hydrotreater, integrating one or more gas and liquidseparators, streams of hydrogen, purge gases, sulfur recovery steps andcommon treated liquids recovery. In another variation such integrationis configured to enable separate treated liquids recovery to enablemeasurement of sulfur content of each separate stream and adjustment ofamount of flow to combination zone so as to form a fuel having an actualsulfur content at or below a target sulfur content. In a variation, thetreated products stream from the upper zone of the hydroconversionreactor zone effluent can be separated by fractionation into more thanone hydroconverted liquid fractions, at least one of such fractionshaving a sulfur content above the target sulfur content which isdirected to a separate hydrotreating zone for contact with hydrogen inpresence of catalyst at hydrotreating conditions to form a reducedsulfur hydrotreated stream having a sulfur content less than the targetsulfur content, and then such hydrotreated stream is combined with otherhydroconverted liquid fractions and with said untreated stream derivedfrom light tight oil to form a fuel having an actual sulfur content ator below a target sulfur content.

In one embodiment, a light tight oil feed has a density API in the rangeof 45 to 55 degrees and said high sulfur fuel oil has a density API inthe range of 14 to 21 degrees, said hydroconverted liquids have adensity API in the range of 26 to 30 degrees, and said combination fuelproduct has a density API in the range of 37 to 43 degrees and a sulfurcontent of less than 0.5 wt. % sulfur. The actual sulfur content offuels of this invention can be adjusted, as disclosed herein, to meettarget sulfur content within an IMO specification for marine fuel or aturbine manufacturer's specification for a combustion gas turbine.

In another embodiment of this invention, a process for co-processingcrude oil with light tight oil and high sulfur fuel oil is provided. Wedefine the “breakpoint”, for purposes of the specifications and claims,in reference to an assay of crude, or other determination method, asplotted with % mass or volume of crude as the x-axis, with sulfurcontent as the y-axis, to be the point at which sulfur content begins torapidly increase from at or near horizontal, or increases exponentially,in terms of high change rate of rise over per unit run, where delta forthe run is change in unit volume of fraction and delta for rise ischange in unit of sulfur content and slope is the rise over run. Theslope of such rise over run starts from near zero or horizontal, rapidlymoves over 0.2 to quickly over 1 moves toward somewhat exponential breakout increases in sulfur content, The breakpoint will vary based on crudeor other feed to the distillation column. The “breakpoint cut” or“sulfur breakpoint cut, thus addresses a means to determine the split inhydrocarbon containing liquids, which boil above the end point of therange for naphtha, for illustration above the end of range ofunstabilized wild straight run naphtha, but below or at the breakpoint,which as noted is the point at which sulfur content begins to rapidlyincrease, or increases exponentially, in terms of high change rate ofrise over per unit run.

We define base “breakpoint cut” or base “sulfur breakpoint cut”, forpurposes of the specification and claims, to mean, with reference to thesulfur content of a fraction, hydrocarbon containing liquids boilingabove the end point of the range for unstabilized wild straight runnaphtha but below or at the breakpoint, where such breakpoint isselected so that when a fuel product stream is formed from combinationof all untreated streams at or below the breakpoint and all streamsabove the breakpoint cut selected to be added to such combination, thecombination fuel has an actual sulfur content that does not exceed atarget sulfur content. In variations, a fuel can be produced inaccordance wherein the target sulfur content is the sulfur breakpoint,or is higher or lower than the sulfur breakpoint, and the combination ofstreams forming the fuel are made efficiently with reference to thebreakpoint so that actual sulfur content of said fuel does not exceedthe sulfur target.

The hydrocarbonaeous feeds, including crude oils and high sulfur oilsthat have a relatively high sulfur, nitrogen and metals content are fedto atmospheric and vacuum distillation and separated into (1) lightoverhead still gases, (2) liquid fractions at or below sulfurbreakpoint, (3) fractions above sulfur breakpoint comprising (A)distillate range fractions comprising sulfur, (B) vacuum gas oil rangefractions comprising sulfur, and (C) vacuum residue comprising sulfur,and (4) purge gases comprising sulfur, such as small amounts sulfurcontaining gases from distillation unit still gases, strippers and otherunit operation overheads. The liquid fractions at or below the sulfurbreakpoint, as untreated liquids, are directed to the combination zoneto form at least a portion of the fuel. Distillate range fractions andvacuum gas oil range fractions to distillate and vacuum gas oilhydrotreaters for contact with addition of hydrogen in presence ofcatalyst at hydrotreating conditions to form one or more hydrotreatedliquids which are directed to a combination zone and purge gasescomprising sulfur. The vacuum residue is directed to an ebullatedresidue hydroconversion zone for contact with addition of hydrogen inpresence of catalyst at ebullated hydroconversion conditions to form (1)one more treated liquids which are directed to combination zone to formpart of the fuel, (2) purge gases comprising sulfur and (3) unconvertedoils which are directed to solvent separation to form (A) solubledeasphalted oil which is directed to residue hydroconversion, eitheralone or combined with vacuum residue, and (B) insoluble pitch which isdirected to pitch treatment. The untreated liquids are combined withsaid treated liquids to form a fuel having an actual sulfur content ator below a target sulfur content. Preferably, at least one of saidhydrotreated streams is an ultralow sulfur stream having 10 ppmwt orless of sulfur which is used to adjust, by reduction or addition of theamount of such stream to combination forming the fuel in a manner tocontrol actual sulfur content at or below a target sulfur content.

Variations of processes of this invention enable substantially allhydrocarbon compositions of said crude oil feed that have been separatedinto fractions to be subsequently recombined to form said fuel which isone liquid fuel product, not multiple hydrocarbon products, excepthydrocarbon compositions comprising those within (i) light overheadstill gases of distillation, (ii) pitch and (iii) streams for sulfur ormetals recovery. The fuels can comprise a combination of hydrocarbonsranging from lowest boiling portion of said untreated liquid fractionfrom said atmospheric distillation to highest boiling portion of streamrecovered from solvent separation and subsequently treated stream ineither a hydrotreating or hydroconversion reactor, recovered andcombined into said fuel. In one variation, at least one of thehydrotreated steams is an ultralow sulfur stream having less than 10ppmwt of sulfur, and the untreated fraction has a sulfur content inexcess of the target sulfur content and said untreated fraction is usedas trim control, by reduction or addition of the amount of suchuntreated fraction to said combination, to form a fuel having an actualsulfur content at or below a target sulfur content. In anothervariation, a first hydrotreated stream is a reduced sulfur stream havinga sulfur content less than 10 ppmwt of sulfur, and a second hydrotreatedfuel fractions is a reduced sulfur stream having a sulfur content in therange of 0.12 to 0.18 wt. % sulfur, and the untreated fraction has asulfur content in excess of the target sulfur content and either saidfirst hydrotreated stream or second hydrotreated stream, or both, areused as trim control, by reduction or addition of the amount of suchsteams to said combination, to form a fuel having an actual sulfurcontent at or below a target sulfur content.

In one variation, the residue hydroconversion and hydrotreating zonecomprises a separate distillate hydrotreating reactor, heavy oilhydrotreating reactor and residue hydroconversion reactor, with eachreactor forming a separate treated effluent, and each treated effluentis separately directed to a shared wall separator to form a commonoverhead gas comprising sulfur and one or more separate reduced gasliquid treated effluents associated with each reactor treated effluentwhich is separately withdrawn from said separator at a rate based uponits respective sulfur content and directed either (a) to saidcombination with said untreated liquid stream to form a fuel having anactual sulfur content at or below a target sulfur content or (b) toreserve storage for subsequent trim control of fuel sulfur content. Incertain variations of processes of this invention, the volume of outputproduct fuel may exceed the total volume of input feeds, where byreasons of volume lift caused, at least in part by hydrogen addition.

These novel processes enable sulfur content of combination fuel to beadjusted to meet a target sulfur content within an IMO specification formarine fuel or a turbine manufacturer's specification for a combustiongas turbine. Thus, the fuels are particularly useful in marine or landbased engines, combustion gas turbines, or fired heaters. Certain fuelvariations derived from combining light tight oil and processed highsulfur fuel oil, wherein the high sulfur fuel oil is processed byresidue hydroconversion, produce a fuel having an actual sulfur contentof 0.5 wt. % or less comprising a range of crude oil derivedhydrocarbons from about C5 to about C20 or more, said hydrocarbonshaving an initial boiling point being the lowest boiling point of anyfraction within untreated streams combined in said fuel and highestboiling point being the highest boiling portion of effluent from solventseparation which is subsequently treated, either by hydrotreating orhydroconversion, and is combined to form a portion said fuel.

FIG. 1 gives a general overview of one embodiment of this invention andshows in simplified form the major components for a process forconversion of hydrocarbonaeous feeds comprising sulfur and metals toform a fuel. A light tight oil feed 1 has preferably been flashed duringprior production, shipment or other handling in basic gas/liquidseparators to separate light entrained gases or has been subject tostabilization, water and sediment removal or other minor conditioning.The light tight oil feed 1 comprises substantially a lighter and middlerange of hydrocarbons having relatively minor amounts of sulfur andmetals and relatively little heavy oils and is directed without addedtreatment to combination zone 600 as an untreated liquid stream. A highsulfur fuel oil comprising sulfur, nitrogen and metals is fed via line41 to a residue hydroconversion zone 401 for contact of such oil 41 withhydrogen in presence of catalyst at residue hydroconversion conditionsin a residue hydroconverter such as an ebullated-bed reactor or othersuitable hydroconversion apparatus selected based on feed composition,within zone 401 to form (1) reactor segment effluent which is separatedinto treated hydroconverted liquids 411 (herein termed “hydroconvertedliquids” as type of treated liquids comprising substantially a fullrange of hydrocarbons from about C5 boiling range up to the minimumboiling point of unconverted oils 409 that are residue fromhydroconversion, purge gases 420 comprising purged hydrogen and offgases, components of liquid petroleum gas, and acid gases comprisingsulfur, and (2) unconverted oils 409. Such separation is preferably beby a form of vacuum distillation, along in some instances of certainfeeds, near atmospheric distillation may be effective to separate theunconverted oils. The unconverted oils 409 are directed to solventdeasphalting in zone 301. Solvent deasphalting separation 301 forms a(A) soluble deasphalted oil 311 which is recycled as feed tohydroconversion reactor in zone 401, either separately or combined withadded high sulfur fuel oil feed 41 to said reactor. Solvent deasphaltingseparation 301 also forms a (B) insoluble pitch 351 which is directed topitch treatment in the utilities island 501. In the variation shown inFIG. 1, the pitch 351 is directed to a utilities island 501 where thepitch is treated. In this example, the pitch can be fired in one or moregasifiers (not shown) for generation of electricity and of at least aportion of hydrogen for said hydroconversion and for capture at least aportion of said metals in gasifier solids which are removed.

The untreated liquids of line 1 are combined with said treated liquids411 to form a fuel in combination zone 600. The fuel 600 thus form hascombined the (i) lighter and middle range hydrocarbons of the lighttight oil feed, condensate or other light feed 1 with many of the (ii)heavier range of hydrocarbons of the high sulfur fuel oil 41 found withtreated liquid effluents 411 of hydroconversion zone 401, which fuel 600has wide range of hydrocarbons comprising those from C5 to C20 orhigher. The fuel so formed has a wide range of hydrocarbons comprisingthose from the lowest boiling with said light tight oil forming saidfuel up to the maximum boiling point of hydrocarbons in line 311 thatare soluble in solvent separation 301 and are subsequent treated withhydrogen in zone 401 and form part of the effluent 411 to form saidfuel. The amount and flowrates of components 1 and 411 can be adjusted,based on their respect sulfur content, so that the fuel 600 has anactual sulfur content at or below a target sulfur content. Forillustration, not limitation, if stream 1 is found to have an elevatedsulfur content at an unacceptable level that makes it unusable forcombining in zone 600, the untreated stream 1 can be fractionated(fractionator not shown), and any higher sulfur heavy bottoms portioncan be directed to an integrated hydrotreater within zone 401 fortreatment and the other portion of stream 1 can remain untreated andpassed to combination zone 600. However, higher sulfur cuts resultingfrom processing upstream of the hydroconverter, such as an atmosphericdistillation bottoms, would not be sent to hydroconversion as part ofstream 41 since it will hydrocrack at hydroconversion conditions,unnecessarily consuming hydrogen, and yielding lighter materials foundoriginally within the light tight oil feed. Such higher sulfur cutsinstead would be directed to a separate hydrotreating zone asillustrated by next variation. In this variation, treated product zoneeffluents of one or more reactor within 401 can separated byfractionation, into more than one hydroconverted liquid fractions, andif at least one of such fractions has a sulfur content above the targetsulfur content, such fraction or fractions can be directed, either aloneor with other similar sulfur content and boiling range streams fromoutside zone 401 to one or more separate hydrotreating zones within zone401 for contact with hydrogen in presence of catalyst at hydrotreatingconditions to form a hydrotreated stream having a reduced sulfurcontent, preferably in the range of 0.5 wt. % or less, or morepreferably to 0.2 wt. % or less and said reduced sulfur hydrotreatedstream is combined with said untreated stream derived from light tightoil or streams remaining from fractionating or other treatment of lighttight oil, to form a fuel having an actual sulfur content at or below atarget sulfur content. In one variation, series or integratedhydrotreaters produce sulfur content at 10 ppmwt or less to 0.1 wt%,depending on amount of ultralow or low sulfur treated liquid needed forcombination stream to have a sulfur content at or below its targetsulfur content.

In the residue hydroconversion system 401 variation shown by FIG. 1,make-up hydrogen containing gas 502 from utilities island 501gasification system in quantities required for hydroconversion, alongwithin internal recycle hydrogen within the residue hydroconversionblock 401, is compressed and heated to effective operating temperatures,pressures, space velocities and pressures, which are adjusted based uponcatalyst selected and other conditions as known in the art to achievedesired level of hydroconversion. The effluent of the zone 401 reactorcomprising treated liquids and a hydrogen containing gas are separatedin a high pressure separator (not shown), with such liquids beingcollected within zone 401, and may directed optionally to fractionation,and the hydrogen containing is recovered. Purge gases comprising sourand acid gases are directed via line 420 to utilities island 501comprising pitch treatment and sulfur recovery systems. Pitch treatmentcan include firing, either alone or with a diluent, in one or moreboilers, for generation of electricity and steam, and optionally havingancillary facilities to reduce or remove sulfur and metal from fluegases and other process gases and a hydrogen generation unit with apressure swing absorption unit. In another variation, pitch treatment isby transfer for asphalt production or use as coker feed for green cokeproduction. In yet another variation, the pitch is fired in one or moregasifiers for generation of electricity and at least a portion ofhydrogen for hydroconversion or hydrotreating and for capture at least aportion of said metals in gasifier solids for metal removal via suchsolids. The optimal selection of how to handle the pitch will depend onthe amount of pitch generated, the availability of low cost hydrogensource, and the potential outlets for the pitch.

Not shown in FIG. 1, but known to those skilled in the hydroconversionart, are various ancillary high, medium and low pressure gas-liquidseparators, stream heaters, gas recycle and purge lines, reflux drumsfor gases or lights and liquid separation, compressors, cooling systems,and other ancillary application. Also, various amine or other sulfurrecovery agent absorbers and stripping systems for sour gas or acid gastreatment would be included in hydroconversion zone 401 if not locatedwithin a common utilities island 501.

Parameters for selection of residue hydroconversion catalyst andadjustment of process conditions of residue hydroconversion zone 401 arewithin the skill of a person engaged in the petroleum refining industryand should not require additional explanation for practice of theresidue hydroconversion segments of this invention. In the reactionzones, the residue hydroconversion catalysts employed include anycatalyst composition useful catalyze the hydroconversion of a heavyhydrocarbon feed to increase its hydrogen content and/or remove sulfur,nitrogen, oxygen, phosphorus, conradson carbon and metal heteroatomcontaminants. Specific catalyst types and various support and particlesize configurations used and residue hydroconversion conditions selectedwill depend on the hydrocarbon feed composition, as well as sulfur andmetals content and heavy carbon residue, of the each of the other feedsfrom recycle or other streams and the desired reduced sulfur and metalscontent of the product stream from the reactor. Such catalyst may beselected from any catalyst useful for the residue hydroconversion of ahydrocarbon feedstock. Publication number US20140221713A1 (U.S. Ser. No.13/758,429) 2014 by Baldassari et al, which is incorporated herein byreference describes a wide range of various suitable residuehydroconversion catalyst as well suitable residue hydroconversionprocesses including variations of integrated residue hydroconversionapparatus. Baldassari et al further summaries variations of catalystcompositions and condition ranges for distillate and heavy oil residuehydroconversion and distinguish over hydroconversion conditions, all ofwhich are known those skilled in the art of residue hydroconversion. Inone preferred embodiment of this invention, the ebullated bedhydroconversion is carried out at a reaction temperature range from 380°C. to 450° C. and a reaction pressure in the range of from 70 bar to 170bar (hydrogen partial pressure), with preferred liquid hourly spacevelocities in the range of 0.2 to 2.0hr-1, and conversion to 550° C.minus would be in the range of thirty percent (30%) to eighty percent(80%).

In another preferred variation, the pitch 351 is fed to an integratedgasification-combined cycle system 501 comprising one or more gasifiersfor partial oxidation of said pitch 351 in presence of steam and oxygenand optionally carbon containing slurry quench, to form syngas, at leasta portion of which is converted to hydrogen which is directed via line502 for use in hydroconversion system 401 and syngas for firing a gasturbine of a combined cycle power unit within the utilities islandsystem 501 for electrical generation within 504 for process uses andother uses, as well as forming hot turbine gases, and also comprising aheat recovery generator to recover heat from such hot gas turbine gasesto produce steam extracted via line 507 internal process use or to drivea steam turbine, for additional electricity generation directed as powervia 504. Each gasifier also produces metals rich soot, which may be inthe form of particulate solids, which comprises metal contaminantsderived from the high sulfur fuel oil and/or other heavy feeds, whichsolids are directed via line 506 from each gasifier for metals removal.Support systems comprise one or more gas treatment units to which allsulfur containing gas streams, whether sour gas or acid gas, from allunit operations are fed for sulfur removal via 508. Preferably suchsulfur removal systems are part of the utilities island of which thegasification system is part. More preferably, one or more sulfurcontaining gas streams are directed to commercial sulfur acid productionas part of overall sulfur removal. The gasification system withinutilities zone 501 will typically include acid gas removal unit and sourCO-shift system that are optimized in capacity and configuration toproduce the required hydrogen from at least a part of the raw syngasproduced within the gasification system.

In the embodiment of a process of this invention shown in FIG. 2, aliquid stream 411 resulting from high sulfur fuel oil feed 41 iscombined with a liquid stream 15 resulting from light tight oil feed 3at combination zone 600 to produce a fuel having an actual sulfurcontent at or below a sulfur content target.

A light tight oil enters the process at line 3 and is directed to afractionator 101 where the feed 3 is separated into at least twofractions: (a) upper zone cut 5 which comprises at least a portion ofthe naphtha range hydrocarbons within light tight oil feed 3 and all ofthe lighter lower range hydrocarbons and (b) a bottoms, comprisingsubstantially that which in not within (a). Fractionator 101 bottoms 11is directed via lines 11 and 15 to combination zone 600 to form aportion of the product fuel. The upper zone naphtha and lower cut 5comprises (i) light still gases which are flashed in a separator (notshown) and passed via line 7 for internal use as process fuel or capturefor other uses and (ii) stream 9 which is primarily naphtha rangehydrocarbons. After removal of light gases, all or part of stream 9 caneither be sent (via lines 9 and 17, connector not shown) directly toline 15 for direct combination to form a portion of the fuel at zone600, or taking into consideration flash point of the combination 600, atleast low flash portion of stream 9 can be passed to a processing unit151, such as a conventional aromatics complex having a catalyticreformer well known in the refining art, wherein stream 9 is contactedwith catalyst in unit 151 to produce byproduct hydrogen 505 and a lighttreated stream 155 recovered via line 159 for non-fuel or other uses.Unit 151 may produce useful byproducts, for example, liquid petroleumgas 153 which can be used internally for process fuel or captured forother uses.

In FIG. 2, a high sulfur fuel oil, either alone or with another heavyresidual or extra heavy crude, enters the process via line 41 and isdirected to a residue hydroconversion zone 401 to produce a very lowsulfur liquid stream 41. As discussed with FIG. 1 above, parameters forselection of residue hydroconversion apparatus and catalyst andadjustment of various process conditions within an integrated residuehydroconversion zone 401 are within the skill of a person engaged in thepetroleum refining industry and should not require detailed explanationfor practice of the residue hydroconversion segments of this invention.In variations of this embodiment as shown, the integrated zone 401comprises a hydroconversion reactor to which the high sulfur fuel oiland other heavy feeds within 41 are directed. Such heavy feeds 41 arepreferably treated in residue hydroconversion zone 401 having anebullated-bed reactor within zone 401 to form (1) reactor segmenteffluent which is separated into treated liquids 411, purge gases 420comprising hydrogen and sulfur and (2) unconverted oils 409. Theunconverted oils 409 are directed to solvent separation 301. Solventseparation 301 forms a (A) soluble deasphalted oil 31 which is recycledas feed to said reactor 401, either separately or combined with addedhigh sulfur fuel oil feed 51 to said solvent separation zone 301.Solvent separation 301 also forms a (B) substantially insoluble metalsrich pitch 351 which the embodiment shown in FIG. 2 is directed to pitchtreatment.

In the utilities variation shown in FIG. 3, the pitch 351 is directed toa boiler where the pitch is fired to generate steam for steam turbinegeneration of electricity 561, wherein at least a portion of the boilerflue flue gases 429 are treated in zone 701, either separately or withzone 401 acid gases 420 within purge and other gas streams fromhydroconversion zone 401, for example, via various amine or other sulfurrecovery agent absorbers and stripping systems for sour gas or acid gasfor sulfur capture and removal via line 565 and, in variations, separatesystems for metals capture and removal via line 563. Not shown in FIG.2, but known to those skilled in the hydroconversion and hydrotreatingart, are various ancillary high, medium and low pressure gas-liquidseparators, stream heaters, gas recycle and purge lines, reflux drumsfor gases or lights and liquid separation, compressors, cooling systems,and other ancillary apparatus. In the variation shown, in addition tooptional byproduct hydrogen 505 from process unit 151, other make-uphydrogen supply to zone 401 is via lines 503 and 509 from hydrogengeneration unit 517 having a hydrogen source 519, for illustration, notlimitation, a natural gas fed steam cracker with a pressure swingabsorption unit, which cracker may be able to use at least a portion ofthe boiler steam from utilities zone 501 as discussed later.

The combined heavy residue feeds to hydroconversion reactor zone 401 aredirected in contact with hydrogen in presence of catalyst at residuehydroconversion conditions in an ebullated-bed reactor within zone 401to form (1) reactor segment effluent which is separated into treatedliquids 411, a portion of purge gases 420 comprising hydrogen and sulfurand (2) unconverted oils 409. Also, various amine or other sulfurrecovery agent absorbers and stripping systems for sour gas or acid gastreatment would be included either in hydroconversion zone 401 orseparate sulfur recovery zone 701 to which high sulfur purge gases 428would be directed. The treated steam 411 is directed to combination zone600 to be combined with untreated stream 15 form the product fuel in amanner whereby the combination is made so that the actual sulfur contentof the fuel product is at or below the target sulfur content.

In the embodiment of a process of this invention shown in FIG. 3, astream of contaminated crude oil comprising sulfur, nitrogen and metalsenters the process via line 2 after pretreatment such as desalting,which is preferred for crude oil. In this example, the crude feed 2 canbe a single crude oil or blends of one or more crude oils or a blend ofa crude oil with, or a separate feed of either a light tight oil or aresidual oil such as high sulfur fuel oil or both. In the variationshown, a crude feed 2 and a light tight oil feed 3 are separatelydirected to an atmospheric distillation column 100, preferably in amanner whereby the light tight oil 3 is fed at or near the upper portionof the crude 2 feed flash zone of column 100 where the feeds areseparated into light overhead gases 4 and multiple cuts. The lightoverhead gases 4 include non-condensable still gases 6 useful as processfuels or can be captured for other uses. In one preferred variation,capital expenditures associated with a stabilization system are avoidedwith respect such overhead gases 4; however, depending on local needs,for example a special marine fuel maximum H2S specification, astabilization system can be included.

In the embodiment shown in FIG. 3, the multiple cuts would include oneor more of streams within these ranges (1) unstabilized wild straightrun naphtha via line 4 at line 16, (2) sulfur breakpoint cut at line 18,(3) light distillate at line 24, (4) medium distillate at line 26, (5) afirst heavy distillate at line 28, (6) atmospheric residual at line 30.Preferably, the combination sulfur break point of steams (1)unstabilized wild straight run naphtha via line 4 at line 16 and (2)sulfur breakpoint cut at line 18 would contain in the range of less than0.06 wt. % sulfur to 0.08 wt. % sulfur if the fuel combination at 600target sulfur content is 0.1 wt% or less sulfur and treated streamssulfur content is less than 10 ppmwt, where flow rates of untreatedsteams 10 and treated streams 65, 75, and 85 to the combination areadjusted so that the fuel combination 600 does not exceed target sulfurcontent. In a variation, an untreated low sulfur, low metals light tightoil stream is fed via line 53 directly to combination 600 in addition tothe combination of lines 10, 65, 75, and 85 to adjust final sulfurcontent and other parameters of combination zone 600.

In FIG.3, the atmospheric residual is directed via line 37, either aloneor with added residual oil feed 35 such as high sulfur fuel oil, to avacuum distillation tower 200 to produce (1) a second heavy distillateat line 32, (2) light vacuum gas oil at line 36, (3) heavy vacuum gasoil at line 38 and (4) vacuum residual at line 50. The vacuum residual50 is directed via lines 57 and 317, either alone or with added residualoil 55 such as high sulfur fuel oil to the an integrated residuehydroconversion and hydrotreating zone 401.

Parameters for selection of integrated residue hydroconversion andhydrotreating apparatus and catalyst and adjustment of various processconditions within an integrated residue hydroconversion andhydrotreating zone 401 are within the skill of a person engaged in thepetroleum refining industry and should not require detailed explanationfor practice of the residue hydroconversion and hydrotreating segmentsof this invention. In variations of this embodiment as shown, theintegrated zone 401 comprises a (A) hydroconversion reactor zone 490 towhich the heaviest, most contaminated feeds are fed via lines 57 and 317such as vacuum residue 50 and added high sulfur fuel oil and other heavyfeeds via line 55, (B) a heavy oil hydrotreating reactor zone 460 towhich heaviest distillates and gas oils are fed via line 39, such asshown those comprising (1) light vacuum gas oil at line 36, and (2)heavy vacuum gas oil at line 38, and can also be fed vacuum oilsseparated within zone 410 from hydroconversion reactor effluent, forexample, by vacuum distillation of reactor liquid product stream, (C) adistillate hydrotreating reactor zone 430 to which the lighter, lesscontaminated feeds are fed via line 20, such as line 29 comprising (1)light distillate at line 24, (2) medium distillate at line 26, (3) afirst heavy distillate at line 28 and line 32 comprising (4) secondheavy distillate and can also be fed distillate range materialsseparated within zone 401 from hydroconversion reactor effluent. Forexample, the second heavy distillate at line 32 can be alternativelydirected to the heavy oil hydrotreater 460 depending on line 32composition and needs to balance the loads on hydrotreater reactorswithin zones 430 and 460 and control sulfur content levels. In suchintegrated residue hydroconversion and hydrotreating zone 401, recycleand make-up hydrogen streams 410 and 414 and purge gas streams 412 and416 have integrated recycle, separation and removal systems known tothose skilled in the refining art. Not shown in FIG. 3, but known tothose skilled in the hydroconversion and hydrotreating art, are variousancillary high, medium and low pressure gas-liquid separators, streamheaters, gas recycle and purge lines, reflux drums for gases or lightsand liquid separation, compressors, cooling systems, and other ancillaryapparatus. In the variation shown, hydrogen supply 503 is from hydrogengeneration unit 517 having a hydrogen source 519, for illustration, notlimitation, a natural gas fed steam cracker with a pressure swingabsorption unit, which cracker may be able to use at least a portion ofthe boiler steam from utilities zone 501 as discussed later.

The combined heavy residue feeds 317 to hydroconversion reactor zone 490are directed in contact with hydrogen in presence of catalyst at residuehydroconversion conditions in an ebullated-bed reactor within zone 401to form (1) reactor segment effluent which is separated, preferably by asecond vacuum distillation unit (not shown) into (1) treated liquids 85comprising (i) naphtha, (ii) middle distillates and (iii) vacuum gasoils, a portion of purge gases 416 and 428 comprising hydrogen andsulfur and (2) unconverted oils 409. Also, various amine or other sulfurrecovery agent absorbers and stripping systems for sour gas or acid gastreatment would be included either in hydroconversion zone 401 orseparate sulfur recovery zone 701 to which high sulfur purge gases 428would be directed, At least a portion of the used catalyst fromhydroconversion reactor 490 ebullated bed, comprising metals and/orother contaminants deposited thereon or other accumulated with thecatalyst during processing within the ebullated bed of the reactor 490is withdrawn via line 421 and replaced by makeup catalyst via line 423,as is known in the art. In one variation, the treated liquids 85comprising (i) naphtha, (ii) middle distillates and (iii) vacuum gasoils are fractionated and the middle distillates are directed to thedistillate hydrotreater 430 and the vacuum gas oils are directed to theheavy oil hydrotreater 460.

The hydroconversion unconverted oils 409 are directed to solventseparation 301. Solvent separation 301 forms a (A) soluble deasphaltedoil 311 which is fed to said hydroconversion reactor 490 or in anothervariation to zone 460, either separately or combined with vacuumresidual 50, with added high sulfur fuel oil feed 55, if any, via lines57 and 317 to said hydroconversion reactor 490. Solvent separation 301also forms a (B) insoluble metals rich pitch 351 which is directed topitch treatment in the utilities island 501. In the utilities variationshown in FIG. 3, the pitch 351 is directed to a boiler where the pitchfired to generate steam for steam turbine generation of electricity 504,wherein at least a portion of the boiler flue flue gases 429 are treatedin zone 701, either separately or with zone 401 acid gases 428, forexample, via various amine or other sulfur recovery agent absorbers andstripping systems for sour gas or acid gas for sulfur capture andremoval via line 561 and separate systems for metals capture and removalvia line 563.

In the variation shown in FIG. 3, the fuel product 600 sulfur content iscontrolled to be at or below a target sulfur content limit level by (a)feeding to the combination 600 unstabilized wild straight run naphtha 16and sulfur breakpoint cut 18, without added treatment of either suchstream, via line 10, then (b) adjusting actual product sulfur level 600by increasing or decreasing amounts to the combination of one or more ofany of (1) streams of light distillate 24, medium distillate 26, firstheavy distillate 28, and second heavy distillate 32 or adding orreducing middle distillates within hydroconverter reactor effluentformed within the integrated zone 401 to the distillate hydrotreaterzone 430, or (2) stream 39 comprising light vacuum gas oil 36 and heavyvacuum gas oil 38 or adding or reducing hydroconverter effluent vacuumgas oils (not shown) formed within integrated hydroconversion (401 ) toheavy oil hydrotreater 460, and (c) then decreasing amounts to thecombination 600 of one or more of any of (1) streams from distillatehydrotreater zone 430 via line 65 which was formed from light distillate24, medium distillate 26, first heavy distillate 28 and/or second heavydistillate 32, and optionally hydroconverter effluent middle distillates(2) streams from heavy oil hydrotreater zone 460 via line 75 which wasformed from light vacuum gas oil 36, heavy vacuum gas oil 38 andoptionally hydroconverter effluent vacuum gas oils or (3) naphtha andother treated liquid effluent 85 form hydroconversion reaction zone 490,if any or all of such needed for any reason to increase the actualproduct 600 sulfur level to the target sulfur level, or (d) increasingamounts to the combination of one or more of any of (1) said streamsfrom distillate hydrotreater 430 via line 65 or (2) streams from heavyoil hydrotreater 460 via line or (3) treated stream from hydroconversionreaction via line 85, if needed for any reason to decrease the actualproduct 600 sulfur content at or below the target sulfur content limitlevel. Multiple sulfur grades can be efficiency produced due to suchfacilitation, for example those fueled targeted for 500 ppmwt sulfurfuel or lower for marine and land based gas turbines or differing rangesfor the same applications at different end-user locations requiringdifferent target sulfur contents.

In variations for use of high sulfur fuel oil having a sulfur contentgreater than the target sulfur content limit level of finished fuel atcombination 600, the high sulfur fuel oil is fed as part of one or moreof the various feeds to one or more of each unit operation. Depending onits sulfur content, high sulfur fuel oil can be added to (a) feed line 2to atmospheric distillation 100 or line 30 via line 35 to vacuumdistillation 200, or (b) via lines 55, 57, and 317 to residuehydroconversion reactor 490, or (c) added to line 20 to distillatehydrotreater 430, either separately or combined with one or more oflight distillate 24, medium distillate 26, first heavy distillate 26 orsecond heavy distillate 32 feeds to said distillate hydrotreater 430, or(d) line 39 to heavy oil hydrotreater 460, either separately or combinedwith one or more of light vacuum gas oil 36 or heavy vacuum gas oil 38or (e) via line 59 to solvent separation zone 301, to form a fuelcombination 600 having an actual sulfur content at or below a targetsulfur content limit level.

In another variation, a clean fuel at combination 600 zone is formed byadding a high sulfur fuel oil, which can have a sulfur content greaterthan the target sulfur content limit to one or more of (a) stream 10formed from unstabilized wild straight run naphtha 16 and sulfurbreakpoint cut 18 without added treatment, depending on sulfur contentof high sulfur fuel oil or is added to (b) stream 65 formed fromdistillate hydrotreater 430 comprising wild naphtha and ultra low sulfurdiesel range materials, or (c) stream 75 formed from heavy oilhydrotreater 460 comprising wild naphtha, ultra low sulfur diesel and asecond reduced sulfur stream or (d) treated effluent 85 fromhydroconversion reactor 85, and adjusting process conditions and sulfurcontents of flows of each treated stream 65, 75 and 85 so that the fuel600 has an actual sulfur content at or below a target sulfur contentlimit level, taking into consideration the sulfur content, if any, ofuntreated steam 10.

In one preferred variation of use of a high sulfur fuel oil in makingfuel composition 600, the sulfur content of such high sulfur fuel oil isdetermined, then the high sulfur fuel oil is either fed as part of thefeeds 55 and 59 to one or more of the solvent separation unit 301 or theresidue hydrocarbon reaction zone 490, as determined by sulfur contentof the high sulfur fuel oil to optimize adjustment of hydroconversionconditions in zone 490 to tailor sulfur content of treated liquideffluent 85 for forming a fuel in zone 600 having an actual sulfurcontent at or below a target sulfur content limit level.

The flowsheets of FIG. 1, FIG. 2 and FIG. 3 showing various intermediateindividual products are for illustration and understanding of the mainproducts and byproducts at effluents of each unit operation depicted. Aselected variation of separation or treatment by each unit operationdepends on crude and feeds selected and optimization of intermediatesproduced to produce fuel at or below target sulfur specification. Forexample, separate treated effluents 65, 75 and 85 shown in FIG. 3 fromhydrotreaters 430 and 460 and hydroconversion reactor 490 can becombined within integrated zone 401 by use of a common gas-liquidseparator (not shown), for example if ultralow diesel produced inhydrotreated 430 is not separated from higher sulfur contenthydrotreated materials produced in hydrotreater 460 or hydroconversionreactor 490 and all treated materials 65, 75 and 85 are combined anddirected as one stream to combination zone 600. As noted, parameters foradjustment of various process conditions within an integrated residuehydroconversion and hydrotreating zone 401 are within the skill of aperson engaged in the petroleum refining industry; for illustration,hydroconversion and hydrotreating conditions will be adjusted to lesssevere to avoid cracking when fewer light ends are wanted in the mix andadjusted to more severe if less heavy ends are wanted.

FIGS. 4 and 5 teach novel fuels and recipes of combinations of one ormore constituents comprising a range of light (L), medium (M) and/orheavy (H) materials to form such fuels.

FIG.4 plots both temperature and density profile against volume fractionfor a reference fuel produced by a process of this invention and showsits (L), (M) and (H) ranges, identified as taught herein.

FIG. 5 shows temperature and density profile against volume fraction ofa reference light condensate that can be used as a ‘top of the barrel’for a combination. That is, such condensate contains naturally occurringmajority of (L) constituents with a minor amount of naturally occurring(M) and little (H)1. The selected condensate, which when combined withadded (H)2 from another source such as a ‘bottom of the barrel’ (H), toformulate a fuel of this invention.

FIG. 5 teaches by example that while the refining ‘warehouse’ inventoryof materials from which to select for a potential combination issomewhat large, the recipe for selection choice herein taught is not.

An essential requirement is that fuels of this invention when formed bycombining a range of hydrocarbons constituents of (L)+(M)+(H), theresulting combination is determined, based on 100 volume percent total,as follows:

-   -   (a) (L)%+(M)%+(H)%=100% and    -   (b) (L)%=(H)%=(100%−(M)%)/2) and    -   (c) if (M)% is zero or otherwise less than 100%, the remainder        is (L)%/(H)% in ratio of 0.4/1 to 0.6/1, and such combination        has the following properties: (1) density within 820 to 880        Kg/M3 at 15° C., (2) sulfur content of 0.25 wt. % or less        and (3) metals content of 40 ppmwt or less. Lower sulfur and        metals are preferred as herein set forth.

To enable one skilled in the refining art to know first how to selectwhat to combine according to the recipe of this invention, potentialcomponents of (L), (M) and (H) are initially summarized by points ofindustry composition reference, then narrowed by limitations of therequirements set forth above and below.

For illustration, with respect to components of “(L)” or “LightConstituent” range, certain components may be within variations found ina refining ‘warehouse’ of local available materials and others may needmanufacture if not locally available. Subject to requirements herein,prospective (L) can include components of naphtha and kerosene rangematerials but not all, for illustration, due to sulfur and densityrequirements for the fuel combination. As used in the specification andclaims, (L) means full range naphtha, having an initial boiling point of38° C. (100° F.) or less having a ninety percent (90%) plus finalboiling point of 190° C. (374° F.) to about 205° C. (401° F.). (L) canbe (a) refined or partially refined, (b) unrefined or (c) extracted andused without being subject to any fractionation, hydrotreating or othertreatment process, except optional separation of light gases or water.For example, certain components of (L) or precursors of (L) are publiclylisted via Platts, an industry offering system; however, offered rangematerials are not based on sulfur breakpoint, as breakpoint is novel andrequires consideration of treatment of materials to be added to thecombination or low sulfur alternatives. Thus, the component descriptionsbelow are guides as to where to look.

Such prospective components of (L) also include, but are not limited to,those within EIA assigned definitions (with degrees F. to C conversionsin brackets) of (i) “Naphtha: A generic term applied to a refined orpartially refined petroleum fraction with an approximate boiling rangebetween [50° C. to 204.5° C](122° F. and 401° F).” and (ii) “Naphthas:Refined or partly refined light distillates with an approximate boilingpoint range between [50° C. to 204.5° C](122° F. and 401° F.). Blendedfurther or mixed with other materials, they make high-grade motorgasoline or jet fuel. Also, used as solvents, petrochemical feedstocksor as raw materials for the production of town gas. Thus, whenpracticing the teaching of this invention, producing or procuring one ormore suitable (L) or Light Constituents, or procuring starting materialsto manufacture such constituents, are known to those skilled in therefining art subject to the requirements herein taught. For example, (L)Constitute preferably has a sulfur content below or at or near thebreakpoint; however sulfur content may be more than breakpoint where thesulfur content of (M) and (H) when combined allow the combination to notexceed the fuel sulfur limit. It is preferred that the (L) heavierportion range end at the sulfur breakpoint for the crude from which itwas produced.

Prospective components of “(M)” or “Middle Constituent” range as usedherein means a refined or partially refined petroleum fraction with anapproximate boiling range between having initial boiling point of about190° C. (374° F.) to about 205° C. (401° F.) a 90% plus final boilingpoint of about 385° C. (725° F.) to 410° C. (770° F.), all subject torequirements herein; however, it is preferred that the lighter portionrange of (M) begins at the sulfur breakpoint for the crude from which itwas produced. Components of (M) can include bottoms portions of lighttight oils heavier than naphtha range. In preferred variations, startingcomponents of (M) comprises a middle distillate combination of about onethird kerosene range and about two thirds diesel range hydrocarbons,subject to other limitations herein and has a density in the range of820 to 880 Kg/M3 at 15° C., per ASTM D4052.

When practicing the teaching of this invention, producing or procuringone or more suitable components of (M) or Middle Constituents are knownto those skilled in the refining art, subject to requirements hereintaught. In many variations found in the refining ‘warehouse’ ofavailable materials, (M) includes, but is not limited to, EIA assigneddefinitions (with degrees F. to C conversions in brackets) of (i)“Middle distillates: A general classification of refined petroleumproducts that includes distillate fuel oil and kerosene”, when as usedherein such boil at or below 385° C. (725° F.), (ii) “Kerosene: A lightpetroleum distillate that is used in space heaters, cook stoves, andwater heaters and is suitable for use as a light source when burned inwick-fed lamps. Kerosene has a maximum distillation temperature of[204.4° C.] (401° F.) at the 10-percent recovery point, a final boilingpoint of [300° C.] (572° F.), and a minimum flash point of [37.8°C](100° F.). Included are No. 1-K and No. 2-K, the two grades recognizedby ASTM Specification D 3699 as well as all other grades of kerosenecalled range or stove oil, which have properties similar to those of No.1 fuel oil.” (iii) “Light gas oils: Liquid petroleum distillates heavierthan naphtha, with an approximate boiling range from [205° C. to 343.8°C.] (401° F. to 650° F.)” and (iv) that portion boiling at or below 385°C. (725° F.) of (iv) “Heavy gas oil: Petroleum distillates with anapproximate boiling range from 343.8° C. to 537.8° C. (651° F. to 1000°F)”, repeating requirement that only such portion boiling at or below385° C. (725° F.) is within (M). (M) comprises also those materialswithin EIA definitions (v) “Kerosene-type jet fuel”, (vi) “No. 1Distillate” (vii) “No. 1 Diesel Fuel” (viii) “No. 2 Distillate”, (ix)“No. 2 Diesel Fuel” (x) “No. 2 Fuel Oil” (xi) “Distillate Fuel Oil and(xii) possibly a portion of a No. 4 Fuel or No. 4 Diesel Fuel, providedfor all of the foregoing the minimum requirements of boiling at or belowabout 385° C. (725° F.) are met. EIA defines diesel fuels broadly toinclude blends comprising residual oils as “Diesel fuel: A fuel composedof distillates obtained in petroleum refining operation or blends ofsuch distillates with residual oil used in motor vehicles. The boilingpoint and specific gravity are higher for diesel fuels than forgasoline.” Thus, since a residual oil may be within a materialidentified as a diesel, those skilled in the refining art will evaluatewhether a tendered diesel is a (M) or (H) based on the factors taught bythis invention. Many diesels which are EIA defined “High Sulfur Diesel(HSD) fuel: Diesel fuel containing more than 500 parts per million (ppm)sulfur” likely fall within (M) or (H), subject to other requirements ofthis invention as further explained herein. However, EIA defined “Lowsulfur diesel (LSD) fuel: Diesel fuel containing more than 15 but lessthan 500 parts per million (ppm) sulfur” and “Ultra-low sulfur diesel(ULSD) fuel: Diesel fuel containing a maximum 15 parts per million (ppm)sulfur” likely fall within (M), but could fall within (H) due to otherrequirements of this invention as further explained herein.

A required attribute of the (M) Constitutent range is that (M) average(referred often as bulk) density for such range should be 820 Kg/M3 at15° C. to 880 Kg/M3 at 15° C. to enable such range to form a portion ofa combination of this invention for the combination density to be 820 to880 Kg/M3 at 15° C., subject to other limitations taught herein. Thatis, individual constituents of (M) may fall outside the range but theaggregate of (M) fall with 820 to 880 Kg/M3 at 15° C.

In variations, (M) Constitutent range will have a sulfur content abovethe breakpoint prior to treatment for removal of sulfur, for example, byhydrotreating disclosed herein; however after treatment, (M) sulfurcontent should be below the breakpoint, except in narrow cases where (M)Constitute may be more than breakpoint if the sulfur content of treated(M), for example as hydrotreater effluent, is combined with treated (H)for example as hydroconverter effluent, and when both are combined with(L), such combination of (L),(M) and (H) to not exceed the fuel sulfurlimit. The higher level of breakpoint selected enables the maximumamount of material within (L) to bypass downstream processing, such ashydrotreating if used for sulfur removal and thereby reduces hydrogengeneration costs and other operational costs. In one variation, (M) issubject to hydrotreating to produce a very low sulfur effluent in therange of about 10 ppmwt and very low or essentially metals free. Variousgrades of certain hydrotreated materials that can be selected for useused as components of (M), or precursors, are publicly listed viaPlatts, a well known industry offering system. If (M) is not present ornor added, then the boundary between (L) and (H) are to meet therequirements of (M).

Components of “(H)” or “Heavy Constituent” as used herein means refinedor partially refined petroleum fractions having initial boiling point ofabout 385° C. (725° F.) to about 410° C. (770° F.) and a final boilingpoint of about 815° C. (1499° F.) or less, subject to requirementsherein taught. Such (H) final boiling point is an attribute of the (H)Constituent that can be known upon procurement inquiry or productiontesting. In one variation, the (H) final boiling point is set by afeedstock and/or a process condition, such as the highest boiling pointof a component of a stream recovered from solvent separation andsubsequently treated in either a hydrotreating or hydroconversionreactor, recovered and combined into said fuel.

One essential attribute of (H) constituent range is that, duringmanufacture, suitable amount of its components have been treated toreduce presence of sulfur and certain heavy asphaltenes and metals, forexample by solvent separation discussed herein above and/or treated byhydroconversion and/or hydrotreating as discussed herein, or othertreatment process, for sulfur and metals reduction to a level to enableits addition to a combination of (L), (M) and (H) to meet sulfur andmetals specifications of the fuels of this invention. Another essentialattribute of the (H) range component is that its contribution to (H)range density, and to the final fuel combination, should enable forminga portion of a combination (L), (M) and (H) of this invention where thefuel combination density is 820 Kg/M3 at 15° C. and less than 880 Kg/M3at 15° C., subject to other limitations taught herein.

Thus, when practicing the teaching of this invention, producing orprocuring one or more suitable components of (H) or Heavy Constituents,or the feedstocks and processes to produce same, are known to thoseskilled in the refining art, subject to the limitations taught herein.In many variations found in the refining ‘warehouse’ of availablematerials, starting materials for components of (H) include, but are notlimited to, EIA assigned definitions of (i) that portion boiling aboveabout 385° C. (725° F.) of (iii) “Heavy gas oil: Petroleum distillateswith an approximate boiling range from 343.8° C. to 537.8° C. (651° F.to 1000° F)”, repeating requirement that only such portion boiling above385° C. (725° F.) is within (H). (H) also comprises “Heavy gas oil:Petroleum distillates with an approximate boiling range from 651° F. to1000° F.” with initial boiling point of about 385° C. (725° F.), (ii)Residual fuel oil: A general classification for the heavier oils, knownas No. 5 and No. 6 fuel oils, that remain after the distillate fuel oilsand lighter hydrocarbons are distilled away in refinery operations. Itconforms to ASTM Specifications D 396 and D 975 and FederalSpecification VV-F-815 C. No. 5, a residual fuel oil of mediumviscosity, is also known as Navy Special and is defined in MilitarySpecification MIL-F-859E, including Amendment 2 (NATO Symbol F-770). Itis used in steam-powered vessels in government service and inshorepowerplants. No. 6 fuel oil includes bunker C fuel oil and is used forthe production of electric power, space heating, vessel bunkering, andvarious industrial purposes and (ii) EIA defined “No. 6 Residual fueloil”.

FIG. 4 illustrates one embodiment of composition of a fuel of thisinvention produced from a process of this invention.

FIG. 4 shows, for a reference crude processed by this invention, twoprofiles against volume fraction: a temperature profile 602 and specificgravity profile 604. That is, in FIG. 4, for both the top chart andbottom chart, x-axis 610 is volume fraction of crude. Top chart y-axis612 shows as data points boiling points in degrees Centigrade forvarious cuts, through which the temperature profile curve 602 is drawn.FIG. 4 bottom chart y-axis 614 shows specific gravity data for thereference crude, through which a density profile curve 604 is drawn.

In and through both the top and bottom charts of FIG. 4, two (2)vertical dotted lines LM 606 and MH 608 are drawn intersecting thetemperature profile 602 and density profile 604 curves.

The vertical lines LM 602 and MH 604 are drawn at selected yield splitsof (L) range 622 and (M) range 624 as volume fractions of the referencecrude. In FIG. 4, the intersection of LM 606 is selected at 205° C. andMH 608 is 385° C., to determine those respective ranges for (L) 622 and(M) 624. For a crude lighter or heavier than the reference, lines shiftto the right or left.

Point 609 represents the end of (H) range including vacuum gas oils cutto 565° C. and deasphalted oil lifted from remaining vacuum residualabove 565° C. The temperature at point 609 will depend on thedeasphalted oil lift, with the understanding that from point 609 to onehundred (100) volume percent representing the pitch is not shown.Temperature point 611 is the heavy vacuum gas oil cut point part oftreated (H) used for the combination, with that portion of (H) 626, frompoint 611 to 609 being the deasphalted oils. Corresponding densitypoints are shown in FIG. 4 as 615 for full range of unprocessed crudeand 613 is a straight line passing through the bulk densities of (L),(M), & (H) for processed crude.

Thus, the highest boiling end point of (L) range 622 and initial boilingpoint of (M) range 624 share a common vertical line LM 606. The highestboiling end point of (M) range 624 and initial boiling point of (H)range 626 share a different common vertical line MH 608. The actualendpoint 609 of the precursor to (H) range 626 is cut off as taught byother embodiments of this invention and discussed in the definition of(H) to remove certain heavier asphaltenes and other complex hydrocarbonsand to substantially eliminate metals and leave a very low sulfur (H)contribution to the final fuel.

FIG. 4 further illustrates, from disclosures herein provided regardingfuel produced by a process of this invention, how to combineconstituents within (L), (M) and (H) to form a fuel composition thatsimulates a fuel of this invention produced from a process of thisinvention. In an overview as one variation, one examines a constituent,and plots density against volume fraction to find a center point of its(M) range within the required 820 Kg/M3 at 15° C. minimum at line 640 to880 Kg/M3 at 15° C. maximum at line 642, that being, the point 630(Density Pivot defined later) at which density versus volume intersectwith the middle of (M) range, plus or minus ten volume percent (+/−10%)or if very little or no (M) range constituents are present, then at animputed point such as at or between where (L) ends (H) begins. Thecenter dark square 630 is the (M) range bulk density mid-point with 631and 633 being bulk density center points for (L) and (H) rangesrespectively.

If a lighter crude than the reference crude is processed by a process ofthis invention to make the fuel, the vertical lines LM 606 and MH 608shift to the right, as do ranges of (L) 622, (M) 624 and (H) 626,meaning there is a greater volume of lighter constituent (L) range 622and less of (H) 626. The Density Pivot 630 moves slightly remains withinthe Density Fulcrum 632 (defined later) even though fuel densitydecreases. The opposite occurs if a heavier crude than the referencecrude is processed by a process of this invention to make the fuel. Thatis the vertical lines LM 626 and MH 628 shift to the left, meaning thereis a greater volume of constituent (H) and less of (L). The fuelcombination Density Pivot 630 point is to remain within the 820 to 880Kg/M3 density zone between lines 640 and 642 even though fuel densityincreases. In the instances of such lighter and heavier feeds, for thecombination fuel, there should be enough (L) and (H) constituents (aswell as (M) constituents if present) with aggregate requisite densitiesto balance each range of (L) and (H) to deliver a fuel having a bulkdensity within the 820 to 880 Kg/M3 fuel combination density zonebetween lines 640 and 642.

Thus very light feeds such as light tight oils or condensates which areprimarily (L) range materials do not have enough heavier materials (M)or (H) to serve as sole material to bring final product bulk densitywithin the Density Fulcrum to have a fuel within 820 to 880 Kg/M3 fuelcombination density zone.

As used in the specification and claims, the terms (a) “Density Fulcrum”means a bulk density between 820 and 880 KG/M3 at 15° C., centerpositioned at or near the Density Pivot (defined next below) withinabout ten volume percent (+/−10 vol %) of a volume fraction range at theDensity Pivot. For illustration, not limitation, measured within 43 to53 volume percent, for nominal 48 volume percent, or 80 to 90 volumepercent for nominal 85 volume percent and (b) “Density Pivot” means thecenterpoint of the Density Fulcrum, so that when equal volumes ofconstituents (L) and (H) are combined, either with or withoutconstituent (M), a balanced density can be achieved. All such citedlines pass through the required bulk Density Fulcrum which serves anessential guiding role in formulation of the fuel to either lift one endrange of the density curve 604 or drop the end of the curve 604, so thatboth ends fall within the 820 to 880 Kg/M3 fuel combination density zonebetween lines 640 and 642, with bulk density for the combination to beat point 630,

Examing the density profile 604 shown in FIG. 4, one is taught that thedensities (bulk) extend are almost in linear profile, give and take asmall variation, but sloped outside the parallel zone range of theDensity Fulcrum 632 and pivoted at or near the center 630 of the DensityFulcrum. As shown, when the density range is from 882 to 880 Kg/M3, at15° C. substantially equal volumes of (L) and (H) will lift and rotatethe line 604 for the total blend to fall in the bulk density rangebetween 640 and 642 of a clean fuel of this invention.

If final combination fuel product density is below the lowest density ofthe Density Fulcrum 632 (e.g. below about 820 lower densityrequirement), then the heating value drops, requiring increased fuelconsumption to achieve same energy effectiveness. If final productdensity is above the highest density of the Density Fulcrum 632 (e.g.above about 880 upper top density requirement) then issues ariseassociated with engine fuel feed and handling systems and other enduses.

It is a surprise that it is possible that (M) can be substantiallyreduced or removed without disturbing balance on the Density Fulcrum andstill form an acceptable fuel of (L) and (H), if all other conditionsare meet. This enables certain top and bottom of the barrelcombinations, with withdrawals of diesel range from (M) yet stillforming an acceptable fuel of remaining (L) and (H).

FIG. 5. illustrates, for example, how to use light tight oil as (L)range constitute ‘top of the barrel’ with another constituent as (H)‘bottom of the barrel’ to form a fuel composition that simulates a fuelproduced from a process of this invention.

In FIG. 5, a condensate is used as reference light tight oil typematerial shown in top portion chart of the FIG.5. This is an example ofa light ‘top of the barrel’ material, having a 53° API, having about 69vol % (L) range 722 ending at line 706 and only has only 28 vol %(M) 724ending at line 708 and about three percent (3 vol %) atmospheric residuebottoms as part of (H)1 shown as 726 contribution toward a finalcombination. The condensate reference material yield curve 702 atvarious temperatures 712 plotted against volume fraction 710 is shown intable chart of FIG. 5. As noted, this reference material assaytranslates as a general approximation to about 69 volume % (L) range 722and 28 volume % (M) range 724 and minor about 3 volume %(H)1 range 726.End point 711 is shown at one hundred (100 volume %) since the bottomsare relatively light gas oil range materials with little heavy residue.If the Density Fulcrum were shown for the reference alone (without added(H)2 shown only in bottom chart of FIG. 5), it would appear far to theright around about 85% of the volume fraction of the original referencewithout added (H)2. Thus to achieve a balance for a combined curvewithin the 820 to 880 Kg/M3 density target range between lines 740 and742, then at least an additional (M) range constituents, or preferably(M)+(H) constituents or more preferably primarily a(H) range materialwith components of (M) such are needed for combination.

In this example shown in the bottom chart of FIG. 5, to each barrel ofthis reference condensate naturally occurring as about 69 volume % (L)722 and 28 volume % (M) 724 and 3 volume % H1 range 726, added fromanother source is 0.69 barrel of (H)2 non-condensate 727, for exampleproduced as a full range effluent from hydroconversion. The center darksquare 730 is the (M) range bulk density mid-point with 731 and 733being bulk density center points for (L) and total (H) rangesrespectively. That combination with (H)2 added forms 1.69 barrel (100volume percent shown in FIG. 5 bottom chart as (L) plus (M) plus (H)1plus (H)2 of formulated clean fuel of this invention as simulated,having a density in with the 820 to 880 Kg/M3 required range, for a fuelproduct API of about 25 to 28 this instance as shown in Table 1:

TABLE 1 ‘Bottom of the barrel’ ‘Top of the barrel’ Hydroconverson MetricCondensate effluent Formulated fuel Constituent (L) (M) (H)1 (H)2 (L) +(M) + (H)1 + (H)2 barrel 0.69 0.28 0.03 0.69 1.69 fraction 0.408 0.1660.018 0.408 1 specific 0.7370 0.8296 — 0.9042 0.8222 gravity

where the formulated fuel in Table 1 meets the low sulfur and metalspecification.

In yet another variation of this invention, the amount of M to thecombination is reduced to near zero. This is done due to shortages insupply of diesels and other materials within the (M) range, being soughtafter for ultra low sulfur diesel highway requirements and great demandfor low sulfur marine and gas turbine applications. In this variation,combinations of essentially equal parts of (L) and (H) are made to formthe formulated fuel, with little or no (M). Choice of a ‘heaviercondensate’ or light tight oil will provide more atmospheric residue,and in some instances, some gas oil range materials, to shift thevertical (LM) lines to the left and the Density Fulcrum will move up asthe density increases from contribution of the heavier light tight oil.

In one embodiment applying above, we have a novel formulated fuelcomprising a combination of one or more constituents of (L), (M), and(H), where based on 100 volume percent total, the respective amountscombined are determined as follows: (a) (L)%+(M)%+(H)%=100% and(b)(L)%=(H)%=(100%-(M)%)/2) and(c) if (M)% is zero or otherwise less than100%, the remainder is (L)%/(H)% in ratio of 0.4/1 to 0.6/1, whereinsuch combination has fuel (1) density within 820 to 880 Kg/M3 at 15° C.,(2) sulfur content of 0.25 wt. % or less and (3) total metals content of40 ppmwt or less. In one variation, sulfur is reduced to 0.1 wt. % orless and metals are reduced to 25 ppmwt or less. In a variation, (M) ispresent from 10 to 90% and remainder is (L)/(H) in ratio of 0.4/1 to0.6/1. In another variation, (M) is changed to be present from 20 to 80%and remainder is (L)/(H) in ratio of 0.4/1 to 0.6/1, and yet anothervariation, (M) is present from 30 to 70% and remainder is (L)/(H) inratio of 0.4/1 to 0.6/1. In a simplified embodiment, (M) ranges from 30%to 70% by volume and the remainder is substantially equal parts of (L)and (H) at (L)/(H) in ratio of 0.9/1 to 1/0.9, and another embodiment(M) ranges from 40% to 60% by volume of the total, density is within 820to 880 Kg/M3 at 15° C., sulfur is 0.25 wt. % or less and metals are 40ppmwt or less.

Thus we have found that a very low 0.1 wt. % sulfur fuel can beformulated or produced by targeting a density within 820 to 880 Kg/M3 at15° C., or less, using manufacturing precurors or constituentscomprising hydrocarbons derived from a combination of light tight oiland hydroconverted high sulfur fuel oil, said fuel having an initialboiling point being the lowest boiling point of any fraction of eithersaid oils at atmospheric distillation conditions and highest boilingpoint being the highest boiling point of the residual portion of saidhigh sulfur fuel oil which is soluble in a solvent suitable for solventseparation. For example, when practicing this invention, if heptane ischosen as the solvent for procurement metrics for combinationconstituent purchase, or for production by use of solvent separationportion of a manufacturing process of this invention, then the highestboiling end, whether treated or untreated, within the combination willbe higher than if pentane is selected as solvent for metric ormanufacture.

We have found that we can use the foregoing disclosed processes toselect or treat precursors of (L)+(M)+(H) to simulate a formulated fuelcombination of a wide range of hydrocarbons useful as a clean turbinefuel having the following properties: (a) sulfur from 0.05 wt. % (500ppmwt) to 0.1 wt. % (1000 ppmwt) per ISO 8754, (b) density from 820 to880 Kg/M3 at 15° C. per ASTM D4052, (c) total metals of 25 ppmwt orless, preferable less than 10 ppmwt, and even more preferably less than1 ppmwt per ISO 14597, (d) HHV from 43.81 to 45.15 MJ/kg, and (e) LHVfrom 41.06 to 42.33 MJ/kg. Flash point will vary based upon the lowestflash point constituent of the combination. We have found variationshave the following additional simulated properties: (a) kinematicviscosity at 50° C. less than 10 mm²/s where 1 mm²/s=1 cSt per ISO 3104,(b) carbon residue is the range of 0.32 to 1.5 per ISO 10370, (c)existent gum is less than 5 per ISO 6246, (d) oxidation stability isabout 0.5 per ASTM D2272, and (e) acid number less than 0.05 mg KOH/gper ASTM D664. For use as marine fuel, reference is made to by testingor computation methods specified by ISO 2817-10.

Thus, the present invention has broad application to production of fuelshaving reduced, low levels of sulfur and other contaminants and to usesof such fuels. Certain features may be changed without departing fromthe spirit or scope of the present invention. Accordingly, the inventionis not to be construed as limited to the specific embodiments orexamples discussed but only as defined in the appended claims orsubstantial equivalents of the claims.

1-47. (canceled)
 48. A formulated combination useful as a fuelcharacterized in that it is formed by combining a range of hydrocarbonsof (L)+(M)+(H) and the resulting final combination has the followingproperties: (a) sulfur from 0.05 wt. % (500 ppmwt) to 0.25 wt. % (2500ppmwt), (b) final combination density from 820 to 880 Kg/M3 at 15° C.,(c) total metals of 25 ppmwt or less, (d) HHV from 43.81 to 45.15 MJ/kg,and (e) LHV from 41.06 to 42.33 MJ/kg wherein, (f) wherein (L) comprisescomponents of naphtha and kerosene range materials, which are refined orpartially refined, unrefined or extracted and used without being subjectto any fractionation, hydrotreating or other treatment process, exceptoptional separation of light gases or water, having an initial boilingpoint of 38° C. (100° F.) or less having a ninety percent (90%) plusfinal boiling point of 190° C. (374° F.) to about 205° C. (401° F.),where (L) range components contribute to (L) range bulk density and tofinal combination density even though individual constituents of (L) mayfall outside said combination density range (g) wherein (M) comprisesrefined or partially refined petroleum fractions having initial boilingpoint of about 190° C. (374° F.) to about 205° C. (401° F.) and a 90%plus final boiling point of about 385° C. (725° F.) to 410° C. (770°F.), where (M) range components contribute to (M) range bulk density andto final combination density, even though individual constituents of (M)may fall outside said combination density, and (h) wherein (H) comprisesrefined or partially refined petroleum fractions having initial boilingpoint of about 385° C. (725° F.) to about 410° C. (770° F.) and a finalboiling point of about 815° C. (1499° F.) or less, where final boilingpoint of (H) is highest boiling point of a component of a stream treatedby solvent separation to reduce presence of asphaltenes and metals thenrecovered and subsequently treated by hydroconversion or hydrotreatingto a level to enable addition of such stream to a combination of (L),(M) and (H) to meet final sulfur content for the combination fuel, andwhere (H) range components contribute to (H) range bulk density and tofinal combination density even though individual constituents of (H) mayfall outside said combination density range.
 49. A fuel in accordancewith claim 48 wherein having one or more the following additionalproperties: (a) kinematic viscosity at 50° C. of less than 10 mm²/swhere 1 mm²/s=1 cSt, (b) carbon residue is the range of 0.32 to 1.5, (c)existent gum is less than 5, (d) oxidation stability is about 0.5, (e)acid number less than 0.05 mg KOH/g, and (f) sulfur from 0.05 wt. % (500ppmwt) to 0.1 wt. % (1000 ppmwt).
 50. (canceled)